DK2534330T3

DK2534330T3 - System and method for positioning in a borehole

Info

Publication number: DK2534330T3
Application number: DK11705225.8T
Authority: DK
Inventors: Jim B Surjaatmadja; Michael Bailey; Timothy H Hunter
Original assignee: Halliburton Energy Serv Inc
Priority date: 2010-02-10
Filing date: 2011-02-10
Publication date: 2014-12-01
Also published as: HRP20141128T1; EP2534330B1; MX2012009290A; CA2789015A1; CA2789015C; AU2011214093B2; AU2011214093A1; WO2011098767A2; US8267172B2; PL2534330T3; EP2534330A2; US20110192599A1; WO2011098767A3

Description

FIELD OF THE INVENTION

[0001] This invention relates to systems and methods of determining a position within a wellbore.

BACKGROUND OF THE INVENTION

[0002] It is sometimes necessary to determine a position within a wellbore, for example, to accurately locate a wellbore servicing tool. A variety of position tools exist for determining a position within a wellbore. Some tools are configured to enable determination of a position within a wellbore by inserting the tool into the wellbore and causing mechanical interaction between the position tool and casing collars, pipe collars, and/or other downhole features within the wellbore such a tool is disclosed for example in US 2003217850. While some mechanical tools are suitable for interacting with a variety of downhole features, the tools may wear or otherwise degrade the components within the wellbore and/or may undergo an undesirable amount of mechanical wear in response to the use of the position tool. Further, some position tools are not well suited for determining a position within a wellbore that comprises components having a wide range of internal bore diameters. Accordingly, there is a need for systems and methods for determining a position within a wellbore without causing undesirable wear to the components within a wellbore and/or to the system itself. There is also a need for systems and method for determining a position within a wellbore for use with wellbores comprising components having a wide range of internal bore diameters.

SUMMARY OF THE INVENTION

[0003] According to one aspect of the invention there is provided a method of locating a wellbore feature, comprising delivering a mechanical position determination tool into the wellbore, selectively causing an undulating curvature of the mechanical position determination tool in response to a change in a fluid pressure, moving the mechanical position determination tool along a longitudinal length of the wellbore, and sensing a change in resistance to continued movement of the mechanical position determination tool.

[0004] According to another aspect of the invention there is provided a mechanical position location tool for a wellbore, comprising pressure actuated elements configured to cooperate to selectively provide an unactuated state in which the mechanical position location tool lies substantially along a longitudinal axis and the pressure actuated elements further configured to cooperate to selectively lie increasingly deviated from the longitudinal axis in response to a change in pressure applied to the mechanical position location tool.

[0005] According to another aspect of the invention there is provided a method of servicing a wellbore, comprising delivering a mechanical position location tool via a workstring into the wellbore, wherein a wellbore servicing tool is coupled to the workstring at a substantially fixed location relative to the mechanical position location tool, increasing a pressure applied to the mechanical position location tool, in response to the increasing the pressure, increasing a deviation of a curvature of the mechanical position location tool from a longitudinal axis of the mechanical position location tool, moving the mechanical position location tool within the wellbore, in response to the moving the mechanical position location tool, engaging the mechanical position location tool with a feature of the wellbore, and servicing the wellbore using the wellbore servicing tool.

BRIEF DESCRIPTION OF THE DRAWINGS

[0006]

Figure 1 is a simplified schematic view of a position determination tool according to an embodiment of the disclosure;

Figure 2 is a schematic orthogonal top view showing a longitudinal axis of the position determination tool of Figure 1 relative to centers of curvature of the position determination tool of Figure 1;

Figure 3 is a an oblique view of an embodiment of a reverser element of the position determination tool of Figure 1;

Figure 4 is an oblique view of an embodiment of a bend element of the position determination tool of Figure 1; and

Figure 5 is a partial cut-away view of the position determination tool of Figure 1 as used in the context of a wellbore for performing a wellbore servicing method using a wellbore servicing device.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

[0007] In the drawings and description that follow, like parts are typically marked throughout the specification and drawings with the same reference numerals, respectively. The drawing figures are not necessarily to scale. Certain features of the invention may be shown exaggerated in scale or in somewhat schematic form and some details of conventional elements may not be shown in the interest of clarity and conciseness.

[0008] Unlessotherwisespecified, any useofanyform of the terms "connect," "engage," "couple," "attach," or any other term describing an interaction between elements is not meant to limit the interaction to direct interaction between the elements and may also include indirect interaction between the elements described. In the following discussion and in the claims, the terms "including" and "comprising" are used in an open-ended fashion, and thus should be interpreted to mean "including, but not limited to Reference to up or down will be made for purposes of description with "up," "upper," "upward," or "upstream" meaning toward the surface of the wellbore and with "down," "lower," "downward," or "downstream" meaning toward the terminal end of the well, regardless of the wellbore orientation. The term "zone" or "pay zone" as used herein refers to separate parts of the wellbore designated for treatment or production and may refer to an entire hydrocarbon formation or separate portions of a single formation such as horizontally and/or vertically spaced portions of the same formation. The various characteristics mentioned above, as well as other features and characteristics described in more detail below, will be readily apparent to those skilled in the art with the aid of this disclosure upon reading the following detailed description of the embodiments, and by referring to the accompanying drawings.

[0009] Disclosed herein are systems and methods for determining a position within a wellbore. In some embodiments, the systems and methods described herein may be used to pass a position determination tool (PDT) through a variety of components within a wellbore while the PDT is in an unactuated state, to actuate the PDT by increasing a fluid pressure within the PDT to cause the PDT to mechanically interfere with a component within the wellbore, and to move the PDT within the wellbore while the PDT is actuated. In some embodiments, a PDT may comprise a pressure actuated bendable tool that, on the one hand, is configured to lie generally along a longitudinal axis when unactuated, but on the other hand, is configured to deviate from the longitudinal axis in response to a change in fluid pressure. A greater understanding of pressure actuated bendable tools and elements of their design may be found in U.S. Patent Nos. 6,213,205 B1 (hereinafter referred to as the ’205 patent) and 6,938,690 B2 (hereinafter referred to as the ’690 patent) which are hereby incorporated by reference in their entireties. In some embodiments, the PDT may comprise a pressure actuated mechanical casing collar locator (MCCL) configured for selective actuation in response to a change in pressure and configured to locate and/or otherwise identify a collar of a tubular, pipe, and/or casing disposed in a wellbore, such as, but not limited to, a collar of a production tubing and/or casing string.

[0010] Figure 1 is a simplified schematic diagram of a PDT 100 according to an embodiment. Most generally, the PDT 100 is configured for delivery downhole into a wellbore using any suitable delivery component, including, but not limited to, using coiled tubing and/or any other suitable delivery component of a workstring that may be traversed within the wellbore along a length of the wellbore. In some embodiments, the delivery component may also be configured to deliver a fluid pressure applied to the PDT 100. For example, in an embodiment where the delivery component used to deliver the PDT 100 is coiled tubing, the coiled tubing may also serve to deliver a selectively varied fluid pressure to the PDT 100 through an internal fluid path of the coiled tubing. While the PDT 100 is shown in an actuated state in Figure 1, the PDT 100 may be delivered downhole and/or otherwise traversed within a wellbore in an unactuated state where the components of the PDT 100 generally lie coaxially along a longitudinal axis 102 of the unactuated PDT 100. In some embodiments, the longitudinal axis 102 may lie substantially coaxially and/or substantially parallel with a longitudinal axis of a wellbore component, such as, but not limited to, a casing string and/or a tubing string through which the PDT 100 may be traversed.

[0011] The PDT 100 generally comprises a plurality of bend elements 104, a plurality of reverser elements 106, and two adapter elements 108. Because the PDT 100 is shown in an actuated state, the bend elements 104, reverser elements 106, and adapter elements 108 cooperate to generally cause deviation of the components of the PDT 100 from the longitudinal axis 102 instead of causing the elements to lie substantially coaxially along the longitudinal axis 102. Such deviation of the PDT 100 components from the longitudinal axis 102 may be accomplished by the cooperation ofthe bend elements 104, reverser elements 106, and adapter elements 108. Cooperation ofthe bend elements 104 and the adapter elements 108 may be accomplished in any of the suitable manners disclosed in the above mentioned ’205 and ’690 patents. Particularly, some aspects ofthe bend elements 104 may be substantially similar to aspects of the members 82, 84, 86, 88 ofthe ’690 patent while some aspects ofthe adapter elements 108 may be substantially similar to aspects ofthe adapter sub 80 ofthe ’690 patent. Transitioning the PDT 100 between the actuated and unactuated states may be initiated and/or accomplished in response to a change in pressure applied to the PDT 100 and/or to a change in a pressure differential applied to the PDT 100 in any of the suitable manners disclosed in the above mentioned ’205 and ’690 patents.

[0012] While the PDT 100 may be configured to lie substantially along the longitudinal axis 102 when in an unactuated state, itwill be appreciated that the interposition of the reverser elements 106 between bend elements 104 may cause an undulation in the general curvature of the PDT 100. As shown in Figure 1, the PDT 100 comprises two reverser elements 106 which may, in some embodiments, cause the actuated PDT 100 to comprise an undulating curvature that generally correlates to a plurality of centers of curvature. For example, the actuated PDT 100 may comprise an undulating curve correlated to three distinct centers of curvature.

[0013] Referring now also to Figure 2 (a schematic orthogonal top view ofthe location ofthe longitudinal axis 102 relative to the centers of curvature described in further detail below), a first center of curvature 110 may be conceptualized as existing generally at a first radial offset from the longitudinal axis 102, in a first angular location about the longitudinal axis 102, and at a first longitudinal location relative to the longitudinal length ofthe PDT 100. Further, a second center of curvature 112 may be conceptualized as also existing generally at the first radial offset from the longitudinal axis 102, also in a first angular location about the longitudinal axis 102, but at a second longitudinal location relative to the longitudinal length of the PDT 100 different from the first longitudinal location of the first center of curvature 110. Still further, a third center of curvature 114 may be conceptualized as also existing at the first radial offset from the longitudinal axis 102, in a second angular location about the longitudinal axis 102 where the second angular location is angularly offset from the first angular location about the longitudinal axis 102, and at a third longitudinal location relative to the longitudinal length of the PDT 100 where the third longitudinal location is located between the first longitudinal location and the second longitudinal location.

[0014] In the above-described embodiment, the first center of curvature 110 and the second center of curvature are located in substantially the same angular location about the longitudinal axis 102 while the third center of curvature 114 is located substantially offset by about 180 degrees about the longitudinal axis from the first center of curvature 110 and the second center of curvature 112. It will be appreciated that in other embodiments, centers of curvatures of a PDT 100 may be located with different and/or unequal radial spacing, different and/or unequal angular locations about the longitudinal axis 102, and/or different and/or unequal longitudinal locations relative to the longitudinal length of the PDT.

[0015] In some embodiments, the undulating curvature of the actuated PDT 100 may simulate a sine wave and/or other wave function that generally provides at least two curve inflection points and/or two transitions between positive slope and negative slope. In otherembodiments, the undulating curvature may not be uniform and/or may comprise more than two curve inflection points and/or two transitions between positive slope and negative slope. Further, while the curvature of the actuated PDT 100 shown in Figure 1 is easily described in terms of a two dimensional curve, it will be appreciated that other embodiments may comprise three dimensional curvatures that cause the curvature of an actuated PDT 100 to exhibit a spiral, corkscrew, helical, and/or any non-uniform three-dimensional curvature.

[0016] Referring now to Figure 3, an oblique view of a reverser element 106 is shown. Reverser element 106 is substantially similar to bend elements 104 but for the location of a reverser lug 116. The reverser element 106 may be described as comprising a reverser longitudinal axis 118 that generally lies coaxially with longitudinal axis 102 when the PDT 100 is in the unactuated state. The reverser element 106 further comprises a reverser ring 120 that has a reverser notch 122 and a reverser channel 124 angularly offset about the reverser longitudinal axis 118 from the reverser notch 122. The relative locations of the reverser notch 122 and the reverser channel 124, in this embodiment, are substantially similar to the relative locations of the notch 94a and the channel 94b of the ring 94 of the ’690 patent. However, unlike the lug 90a of the ’690 patent, the reverser lug 116 is angularly aligned with the reverser channel 124 rather than the reverser notch 122. Accordingly, interposition of the reverser element 106 between bend elements 104 provides the undulating curvature of the actuated PDT 100 with the above described curve inflection point and/or transition between positive slope and negative slope. Of course, in other embodiments, the relative angular locations of the reverser lug 116, the reverser notch 122, and the reverser channel 124 may be different to provide any one of the above-described three-dimensional curvatures.

[0017] Referring now to Figure 4, an oblique view of a bend element 104 is shown. The bend element 104 may be described as comprising a bend longitudinal axis 126 that generally lies coaxially with longitudinal axis 102 when the PDT 100 is in the unactuated state. The bend element 104 further comprises a bend ring 128 that has a bend notch 130 and a bend channel 132 angularly offset about the bend longitudinal axis 126 from the bend notch 130. The relative locations of the bend notch 130, the bend channel 132, and a bend lug 134, in this embodiment, are substantially similar to the relative locations of the notch 94a and the channel 94b of the ring 94 of the ’690 patent. In other embodiments, the relative angular locations of the bend lug 134, the bend notch 130, and the bend channel 132 may be different to provide any one of the above-described three-dimensional curvatures.

[0018] Referring now to Figures 1 and 4, one or more bend elements 104 may be provided with one or more feature locators 136. In an embodiment, the feature locator 136 is generally formed as a wedge shaped protrusion extending radially from a body 138 of the bend element 104. In this embodiment, the feature locator 136 comprises an engagement surface 140 and a slip surface 142. Each of the engagement surface 140 and the slip surface 142 extend from the body 138 to an outermost radial surface 144. However, the slope of the engagement surface 140 and the slope of the slip surface 142 are different so that when the feature locator 136 interacts with a feature of a wellbore, such as a casing collar 146 of a casing 148, a force required to disengage the feature locator 136 may be different in a first longitudinal direction as compared to a force required to disengage the feature locator 136 from the feature in a second and opposite longitudinal direction. In other embodiments, a feature locator 136 may extend continuously (or discontinuously, e.g., in discrete segments) about the entire circumference of the body 138. In an embodiment, casing collar 146 may comprise a circumferential notch and/or a groove configured to engage the feature locator 136. In other embodiments, the feature locator 136 may comprise a coded profile configured to interact with selected ones of wellbore features to the exclusion of other wellbore features (e.g., selectively engaging mechanical structures and/or profiles). It will be appreciated that the feature locator 136 may be provided in a reversed longitudinal direction so that the relative forces required to engage, disengage, and/or avoid interaction with a wellbore feature may be directionally reversed.

[0019] In operation, the PDT100 may be delivered into a wellbore or into a component of a wellbore, such as a casing 148 of a wellbore. Generally, the PDT may be delivered and/orotherwise deployed into a wellbore while the PDT 100 is in an unactuated state so that the components of the PDT 100 lie substantially along the longitudinal axis 102. The longitudinal axis 102 may be substantially coaxial with a longitudinal axis of the casing 148. By delivering the PDT 100 to a desired location within the wellbore while the PDT 100 is not actuated (and thereby minimizing contactduring delivery), the PDT 100 may cause very little wear to the casing 148 and the PDT 100 itself during the delivery and/or deployment into the wellbore. Such delivery and/or deployment of the PDT 100 into the wellbore is monitored to provide operators and/or control systems feedback necessary to provide an estimated or educated guess of where within the wellbore the PDT 100 is located. Many techniques exist for calculating the estimated located of the PDT 100 during such delivery and/or deployment. A few techniques may include one or more of measuring a length of workstring and/or coiled tubing used to deploy the PDT 100, measuring and/or monitoring a weight of the delivery device, and/orany other suitable method of estimating a location of the PDT 100 within the wellbore.

[0020] Such an estimated location of the PDT 100 may be correlated with knowledge of the wellbore contents so that upon reaching an estimated depth or longitudinal location within the wellbore, the user and/or control system may reasonably expect that a wellbore feature such as a casing collar 146 may be near the PDT 100. Once the PDT 100 is deployed so that feature locator 136 is thought to be further downhole than the feature 146, the PDT 100 may be actuated. Such actuation of the PDT 100 may occur in response to a change in a fluid pressure applied to the PDT 100. In some embodiments, a fluid pressure may be increased within a workstring and/or coiled tubing that is connected to the PDT 100. The PDT 100 may be configured so that in response to the increase in fluid pressure delivered to the PDT 100 may cause the above described deviation of the PDT 100 at least until so much deviation is caused to press the feature locator 136 against an interior wall of the casing 148 generally in a first radial direction. In some embodiments, the feature locator 136 is biased against the interior wall of the casing 148 while other portions of the PDT 100, in some embodiments, the adapters 108, are similarly pressed against the interiorwall of the casing 148 but in a direction opposite to that of the first radial direction. In some embodiments, the feature locator 136 may apply a force of about 100-5001 bf against the interior wall of the casing 148. Of course, in other embodiments, a PDT 100 may be configured to apply any other suitable force against the interior wall of the casing 148.

[0021] With such pressure applied to the PDT 100 and the PDT 100 being in an actuated state as described above, the PDT 100 may be moved longitudinally within the wellbore so that the feature locator encounters a wellbore feature such as a casing collar 146. In the embodiment shown, the actuated PDT 100 may be moved upward in the casing 148 until the feature locator 136 is at least partially received within the casing collar 146 (e.g., within a notch, groove, and/or lip associated with and/or defined by the casing collar). Upon such entrance of the feature locator 136 within the casing collar 146, the engagement surface 140 may contact a portion of the casing collar 146 in a manner that increases resistance to further longitudinal movement of the PDT 100. In some embodiments, the required amount of force to dislodge a feature locator 136 from a casing collar 146 may be about 11001 bf when the PDT 100 is internally pressurized at about 1000psi (6.89 MPa). It will be appreciated that in other embodiments, a PDT 100 may be configured to require a different amount of force to be dislodged from a wellbore feature and/or the magnitude of internal pressure required within a PDT 100 to result in varying degrees of actuation of a PDT 100 may be different. An operator and/or control system may detect the increase in resistance to moving the PDT 100 and determine that the feature locator 136 is in a particular location based on the already known structure and contents of the wellbore. Further, in other embodiments, a PDT 100 may be configured to dislodge a feature locator 136 from a wellbore feature in response to decreasing an internal pressure within the PDT 100 rather than or in addition to forcibly pulling the PDT 100 from engagement with the wellbore feature.

[0022] After such identification of a particular location within the wellbore using the PDT 100 in the actuated state, the PDT 100 may be unactuated by reducing the pressure applied to the PDT 100. After sufficient reduction in applied pressure, the PDT 100 may disengage the internal wall of the casing 148, allowing removal and/or subsequent delivery and/or location of additional positions. In some embodiments, positive identification of a particular location may be considered successful when the PDT 100 is apparently pulled free from association with a casing collar 146 with an expected amount of pulling force. If a wellbore servicing tool is attached to the delivery device that has delivered the PDT 100, calculations regarding the elastic strain of the delivery device and/or system may be used to accurately move the delivery device by a desired length within the wellbore to locate the wellbore servicing tool in a desired and/or known location relative to the position identified by the PDT 100. Some examples of wellbore servicing tools and methods that may be used in combination with the PDT 100 include, but are not limited to, pinpoint fracturing systems and methods, tubing punching systems and methods, perforation gun systems and methods, systems and method for setting zonal isolation devices and packers, systems and methods for acid work, and/or any other wellbore servicing system and/or method that may benefit from accurately locating the wellbore servicing tool within a wellbore.

[0023] Referring now to Figure 5, a partial cut-away view of a PDT 100 as deployed into a wellbore 200 is shown. The wellbore 200 comprises a casing 202 that is cemented in relation to the subterranean formation 204 through the use of cement 206. A tubing string 208 (e.g., production tubing) is disposed within the casing 202 but does not extend beyond a lower end of the casing 202. The wellbore 200 comprises a plurality of wellbore features discoverable and/or identifiable by the feature locator 136. For example, the wellbore 200 comprises, in a nonlimiting sense, a lowerend ofthe casing 202, casing collars 210, a lowerend 212 of the tubing string 208, and tubing string collars 214. In this embodiment, the PDT 100 may be used to locate a plurality of the wellbore features even though the features are associated with wellbore components having vastly different internal diameters. The tubing string 208 is received within the interior of the casing 202 and the delivery device, in this case a coiled tubing 216 device, is received within the interior of the tubing string 208. In some embodiments, the internal diameter ofthe casing 202 may be about 7 inches, the internal diameter of the tubing string 208 may be about 5 inches, and the largest diameter of the PDT 100 (in this embodiment around the feature locator 136) may be about 3 inches. It will be appreciated that due to the flexible nature of the PDT 100, the PDT 100 may be delivered through the relatively smaller diameter ofthe tubing string 208 to thereafter locate wellbore features associated with the relatively larger diameter of the casing 202. It will be appreciated that the PDT 100 may be used to sense and locate wellbore features of wellbore components having a great variability in internal diameter. In some embodiments, the PDT 100 may be capable of being delivered through an internal diameter of the tubing string 208 that is about 5% to about 80% smaller than the internal diameter of the casing 202, alternatively about 5% to about 15% smallerthan the internal diameter ofthe casing 202, alternatively about 10% smaller than the internal diameter of the casing 202.

[0024] In some embodiments, the PDT 100 may be used to accurately locate a wellbore servicing device 220, to optionally lock the wellbore servicing device 220 in place within the wellbore 200, to thereafter perform a wellbore servicing operation using the wellbore servicing device 220, and to optionally repeat the locating the wellbore servicing device 220 and perform the wellbore servicing operation accurately at various locations within the wellbore 200 despite the need to pass the PDT 100 through relatively small internal component diameters. In this embodiment, the wellbore servicing device 220 is also carried by the coiled tubing 216 device and is generally fixed relative to the PDT 100. In some embodiments, the PDT 100 and the wellbore servicing device 220 may both be carried and/or delivered by a workstring (and/or any other suitable delivery device) and the wellbore servicing 220 may be coupled to the workstring at a substantially fixed longitudinal location along the work string relative to the PDT 100.

[0025] In an embodiment where the wellbore servicing device 220 is a pinpoint fracturing device, the wellbore servicing device 220 and the PDT 100 may be delivered through the tubing string 208 into an open interior of the casing 202 and below the lower end 212 of the tubing string 208. When the PDT 100 is estimated as being located in the above described position below the lower end 212, pressure may be increased to the PDT 100 via the coiled tubing 216 device to actuate the PDT 100 and cause the shown deviation from the longitudinal axis. The PDT 100 may be dragged upward until the feature locator 136 engages the casing collar 210. The PDT 100 may continue to be pulled upward until the feature locator 136 is judged as having become lodged in the casing collar 210. Next, the pressure delivered through the coiled tubing 216 may further be increased to perform pinpointfracturing atthedesired location relative to the located casing collar210. After discontinuing the pinpointfracturing, the above described methods may be used to subsequently locate one or more of the lower end 212 of the tubing string 208, and the tubing string collar214 and to perform an associated pinpoint fracturing or other services relative to the located wellbore features. It will be appreciated that in other embodiments, the location of the wellbore servicing device 220 may be selected as any location relative to the located wellbore features by using the above-described techniques of adjusting location ofthe PDT 100 through actuating and/or unactuating the PDT 100. Further, the location ofthe wellbore servicing device 220 may be adjusted to compensate for any jumping of the delivery device if the wellbore feature is located by dislodging the feature locator 136 from the wellbore feature.

[0026] Generally, this disclosure at least describes systems and method for locating collars in wellbores despite the need to trip a mechanical collar locator through wellbore components having vastly differing internal diameters. Further, this disclosure makes clear that wellbore features may be accurately located by a mechanical collar locator using systems and methods that provide for selective engagement with wellbore features rather than mandatory engagement with wellbore features that are outside an easily estimated location within the wellbore. The systems and methods disclose a position determination tool that can located one or more of casing ends, casing collars, tubing ends, tubing collars, profile nipples, coded profile nipples, and other wellbore features using a single tool and in a single trip of the tool downhole. The disclosure further specifies that accuracy of wellbore feature location may be improved by one or more of recording and/or monitoring a weight of wellbore components within the wellbore and/or compensating for elastic strains of various delivery devices.

Claims

A method of positioning a borehole feature, comprising: introducing a mechanical positioning tool (100) into the borehole (200); moving the mechanical positioning tool (100) along a longitudinal length (102) of the borehole (200); and detecting a change in resistance to the continued movement of the mechanical positioning tool (100); characterized in that the method comprises selectively causing a wave-shaped curvature (110, 112, 114) of the mechanical positioning tool (100) in response to a change in fluid pressure.

The method of claim 1, further comprising: providing engagement between the mechanical positioning tool (100) and a borehole feature (200), optionally wherein the borehole feature is selected from a group of borehole features consisting of one end of a liner and end. of a pipe, a casing collar, a pipe collar, a profile nipple and a coded profile.

The method of claim 2, further comprising: increasing a traction force to disengage the mechanical positioning tool (100) from the borehole pull; or reducing the pressure to disengage the mechanical positioning tool (100) with the borehole pull.

The method of claim 3, further comprising calculating an elastic load to improve a position determination.

A mechanical positioning tool (100) for a borehole, comprising: pressure-activated elements (104, 106) configured to cooperate to selectively provide an unactivated state in which the mechanical positioning tool (100) lies substantially along a longitudinal axis (102) and the pressure-actuated elements (104, 106) are further configured to cooperate to selectively lie diverging from the longitudinal axis (102) in response to a change in pressure applied to the mechanical positioning tool (100); characterized in that pressure-activated elements comprise a reversing element (106) configured to cause a turning point for a curvature of the mechanical positioning tool (100) when the tool is in the activated state.

The mechanical positioning tool (100) of claim 5, wherein the reversing element (106) is configured to cause a change in a slope sign for a curvature of the mechanical positioning tool (100) when the tool is in the activated state.

The mechanical positioning tool of claim 5 or 6, wherein the reversing element (106) comprises a longitudinal axis (118) and a reversing channel (114) substantially angularly disposed about the longitudinal axis (118) with a reversing tab (116) of the reversing element (106).

A mechanical positioning tool according to any of claims 5 to 7, further comprising a bending member comprising a longitudinal axis and a tensile locator projecting radially from a body of the bending member.

The mechanical positioning tool (100) according to claim 8, wherein the tensile locator (136) is configured to selectively engage with a borehole feature (200) and optionally wherein the borehole feature is selected from a group of borehole features consisting of one end of a liner , and one end of a pipe, a casing collar, a pipe collar, a profile nipple and a coded profile.

A method of servicing a borehole (200) comprising: introducing a mechanical positioning tool (100) according to any one of claims 5 to 8 via a work string in the borehole (200), wherein a borehole service tool is connected to the work string of one. significant fixed position relative to the mechanical positioning tool (100); movement of the mechanical positioning tool (100) in the borehole (200); in response to the movement of the mechanical positioning tool (100), engaging the mechanical positioning tool (100) with a borehole pull; and servicing the wellbore using the wellbore servicing tool; characterized in that the method comprises selectively causing a wave-shaped curvature (110, 112, 114) of the mechanical positioning tool (100) in response to a change in fluid pressure.

The method of claim 10, further comprising: prior to moving the mechanical positioning tool (100) in the borehole (200), increasing the deflection of the curvature at least until a tensile locator contacts a wall in the borehole (200).

The method of claim 10 or 11, wherein said mechanical positioning tool (100) is passed through a first inner diameter tube (208) and said mechanical positioning tool (100) is guided to a liner (202) having a second inner diameter. the first inner diameter being smaller than the second inner diameter by between 5% and 80% before substantially increasing the deflection; and / or wherein the curvature comprises a three-dimensional curve.

A method according to any one of claims 10 to 12, further comprising: after servicing the borehole (200), reducing the curvature; moving the mechanical positioning tool (100) into a space having a smaller diameter and providing engagement between the mechanical positioning tool (100) and a borehole feature attached to the smaller diameter.

A method according to any one of claims 10 to 13, wherein the borehole service tool is selected from a group of borehole service tools consisting of fracture tools, pipe punching tools, perforation cannon tools, zone insulation tools, packer tools and sewing tools.

The method of any one of claims 10 to 14, wherein the borehole service performed is selected from a group of borehole services consisting of fracturing services, pipe punching services, perforation cannon services, zone insulation services, packer services, and acid work services.